As generally known, a subsea multiphase pump, particularly as employed in marine-based oil fields, is typically configured for pumping a combination of petroleum, water, natural gas, and, at times, small particulates (such as sand). Typically, a “pump suction flow,” in the form of a fluid mixture of liquid, gas and solids, travels through the production flow line to the multiphase pump. The pump thus actually pumps a combination of pump suction flow along with any recirculated liquid from the pump discharge.
Twin-screw multiphase pumps have been demonstrated to work admirably in petroleum applications. However, such pumps require a minimum of liquid in the multiphase mixture to maintain a seal between the screw flanks and the screw tips and casing, which requires careful attention in the detailed systems design.
In multiphase service, when this liquid minimum is not present, the pump ceases to pump but still continues to rotate, thus defeating the purpose of the installation. In a subsea installation, the cost of the pumping system is high enough that the loss of production with no boost represents a substantial loss of revenue.
Additionally, when the pump ceases to produce flow against a pressurized discharge line, the liquid in the discharge tends to leak back into the pump. This heated liquid is continuously “regurgitated”, maintaining pump head but not generating any pump flow. The power used to compress gas, which also is regurgitated to the pump suction, will heat the liquid phase and the pump rotors. The heat will remain in the absence of a mass flow, and the pump can thus be damaged if it is not shut down.
In oil fields in particular, there is generally some uncertainty about the size of gas “slugs” that naturally occur in the flowing multiphase oil and gas mixture. Loss of liquid for short periods of time (e.g., fractions of a second) is sufficient to cause the pump to cease pumping even though it continues to run. The transport time for a fluid element, between entering the pump screw entrances and exiting the pump is typically 5-8 revolutions, or typically 0.16-0.27 second for a pump operating at 1800 rpm).
A “GLCC”, or Gas Liquid Cylindrical Cyclone, provides an arrangement for separating gas and liquid from a multiphase mixture. This technology utilizes a vessel with a tangential inlet to form a vortex. Separation of the multiphase fluid occurs due to centrifugal, gravitational and buoyancy forces. Known arrangements abound (see, e.g., U.S. Pat. No. 5,526,684 to Chevron). Typically, a GLCC will be interposed between a pump and an outlet line.
A common approach to ensuring continuous liquid flow, when this is not the norm in an oil field flow line, is to employ recirculation. In recirculation, liquid is separated in the discharge of the pump and some portion of it, e.g. ˜5% of the pump's full volumetric flow regardless of speed, is throttled back to the pump suction. This same liquid can be reseparated at the pump discharge, while the pump can continue to pump and compress an incoming single-phase gas slug indefinitely.
Any recirculation, of course, detracts from pump efficiency in that the liquid recirculated reduces the capacity of the pump, and volumetric efficiency is thus reduced. Additionally, work is required to pump the recirculated fluid back to the discharge pressure condition. In effect, the need for recirculation normally presents a requirement for more energy and a larger pump to do a particular job.
Gas that is entrained with the recirculation liquid is even worse for pump performance. The gas expands upon exiting the recirculation-throttling device, and as a result reduces the volume of suction flow by a factor corresponding to the pressure ratio times its volume at discharge pressure. In effect, 1 cu. ft of gas that is carried under with the liquid phase, and which is recirculated can become 5-6 cu. ft at suction conditions, depending on the pressure ratio across the pump. Additionally, compressive work has to be performed on this gas to recompress it to discharge conditions. Consequently, a need exists to provide good efficiency in limiting free gas (vs. gas in solution) from the liquid being recirculated.
However, several provisions typically need to be addressed. For one, recirculated liquid is typically heated by the compression of the gas during multiphase operation and therefore increases the pump suction temperature. In the event that the only incoming fluid is gas, then sufficient mass flow to remove the heat will not be present and the recirculated liquid will heat up. If liquid does not reach the pump, this heating process goes forward continuously until the pump is damaged or automatically shut down based on the discharge temperature.
Additionally, the discharge separation presents an efficiency in separating the liquid from the gas. For instance, in a GLCC, liquid that is entrained with the gas flow goes out of a GLCC at the recombination point and is lost out the discharge flow line; this is known as liquid carryover. A separator with good efficiency minimizes this loss of liquid. The larger the volume of liquid that can be retained in the recirculation vessel (or vessels attached to the recirculation vessel), the longer the system can stay in operation without running out of liquid or overheating.
Further, since the liquid phase carries the particulates (typically sand and rust), if sufficient velocity of the liquid is not maintained through the separator then these particulates tend to settle out of the liquid and accumulate. Once they have sufficiently accumulated, they can be recirculated in higher concentrations through the pump either as a result of transients (stop-starts) or of just having the natural accumulation collapse into the recirculation line. Typical topside systems have cleanout ports to keep this from happening, but this is undesirable for subsea systems where intervention is limited or difficult. Accordingly, subsea systems typically need to employ liquid velocities high enough to keep particulates in suspension during all times of normal operation.
In view of the foregoing, a compelling need has been recognized in connection with resolving the issues framed above with regard to pump recirculation.
From another standpoint, naturally occurring flow in a multiphase pipeline produces a variety of flow profiles, such as annular, wave and “slug” flow profiles. Slug flow, for its part, is represented by alternating volumes of gas and oil. For a given line size, gas volume, liquid density, liquid viscosity and pressure, these slugs tend to present a recurring pattern and accordingly form waves with a natural frequency and a shape for the liquid and gas phases. These waves exhibit a variability that can be characterized in frequency with a mean and standard deviation (although these properties are rarely known explicitly).
If the production pipeline or local pump connections experience abrupt changes in elevation, however, the wave variability can change adversely such that the liquid slugs will resemble a periodic square wave with little liquid in the leading and trailing edges of each slug. In this and other cases, slugs can thus end up presenting fluid to the pump as only a gas phase, or at least as a gas phase with a liquid content lower than the minimum required to provide a seal.
Consequently, if such gas-dominated slugs are long in duration (at least long enough for a slug to pass through the pump, or likely fractions of a second) then the pump will lose “prime”. Because the pumping systems at hand typically run continuously with slug periods in the 2-10 second range, a large population of slugs are normally generated in continuous operation. As a consequence, examples of the entire population of plus or minus 3-sigma slugs are experienced frequently (e.g., daily) and even examples 6-sigma slugs are experienced periodically (e.g., monthly).
As such, failure of the incoming flow to contain a minimum amount of liquid, e.g. ˜5% of the full flow rating of the pump, can result in a loss of prime and, thus, flow stagnation and heat-up issues within the pump as mentioned further above.
A conventional countermeasure involves the provision of temperature sensors and, in that connection, automatic pump shutdown protection. While this indeed proves to be an effective measure for protecting the pump, overall operability and efficiency still remain major issues, since unplanned pump shutdowns will clearly result in upsets to production and processing facilities. Restarting the pump, flow line, and other components, potentially can take several hours and require other resources such as gas lift and MEG (Mono-Ethylene Glycol) injection.
In view of the above problems, strides have indeed been made towards minimizing or eliminating the loss of prime events in twin-screw multiphase pump operation, albeit with less than optimal results. The use of liquid recirculation, as discussed further above, has proven to be effective, while presenting disadvantages. Another approach involves separating the liquid in the suction and metering it into the pump. If the capacity of such a separator is large enough, the pump can end up traversing long periods where the liquid in the incoming fluid satisfies the ˜5% threshold by combining liquid retained in the separator with the incoming fluid stream. In subsea applications however, larger tanks and separate metering pumps can be impractical to implement because of weight constraints and the desire to avoid complexity and increase reliability. A practical suction separator for subsea use can be designed to handle variations in the incoming slug flows, if the design scope is limited to the variation anticipated by the pump capacity and well yield. For situations where there is no correlation to pump capacity and well production, such as start-up or system upsets, the recirculation system has to be used.
Accordingly, in view of the foregoing, yet another compelling need has been recognized in connection with implementing a more efficient and cost-effective solution in connection with liquid slug management and distribution.